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November 14, 2024

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CAISO Receives FERC Approval to Increase Soft Offer Cap

FERC has approved CAISO’s request to increase its capacity procurement mechanism (CPM) soft offer cap from $6.31/kW-month to $7.34, which CAISO states would better reflect inflation, labor rights and higher bilateral capacity prices (ER24-1225).The increase also would better position the ISO to maintain reliable grid operations in the summer, the order reads. 

The soft offer cap, referenced when load-serving entities bid offers into the market to resolve resource adequacy deficiencies, is based on fixed operation and maintenance costs, ad valorem taxes and insurance costs of a reference unit, plus a 20% adder. 

According to its tariff, CAISO is required every four years to conduct a stakeholder process and evaluate whether to update the CPM soft offer cap. In May 2023, the California Energy Commission provided CAISO with a study demonstrating CAISO’s soft offer cap doesn’t adequately reflect fixed costs and should be increased to $7.34/kW-month.  

“CAISO contends that the proposed soft offer cap is also high enough to ensure contributions to fixed cost recovery and low enough to provide appropriate market power mitigation,” the April 25 FERC order states. “CAISO adds that the proposed soft offer cap will create greater incentives for resources to accept voluntary CPM designations.” 

Motions to intervene were filed by consumer advocacy organization Public Citizen, Calpine, Pacific Gas and Electric, the California Department of Water Resources’ State Water Project, the city of Santa Clara and the Northern California Power Agency. CAISO’s Department of Market Monitoring filed comments supporting the tariff provision. 

“DMM supports the proposed tariff revision to better position the CAISO to maintain reliable grid operations and increase incentives for resources to accept voluntary CPM designations,” DMM’s letter to FERC reads. “In addition, accepting the amendments will allow for the CAISO and its stakeholders to focus on a more comprehensive set of changes needed in the overall CPM and resource adequacy framework.” 

CAISO plans to implement the changes by early June. 

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Wildfire Litigation Poses Threat to Xcel Energy

Xcel Energy said it expects to incur a financial loss from Texas wildfires that could have a “material adverse effect” on the company’s bottom line. 

The Minneapolis-based company has acknowledged distribution poles belonging to its Southwest Public Service Co. subsidiary sparked the February Smokehouse Creek fire in the Texas Panhandle north of Amarillo. The fire, the largest in state history, consumed more than 1 million acres before being contained. 

“I’ve been to the Panhandle, and I’ve witnessed the impacted areas,” Xcel CEO Bob Frenzel told financial analysts April 25 during the company’s first-quarter earnings call. “I can speak for the entire Xcel Energy team when I say that we are saddened by the losses and we will stand with the Panhandle community as we recover, rebuild and renew that area as we have for over 100 years.” 

Xcel has disputed claims that it acted negligently in maintaining and operating its infrastructure. It faces 15 lawsuits from the fire and is processing the 46 loss claims it has received. The company recorded a pretax charge of $215 million to cover losses before insurance. 

But if the company is liable and must pay damages, the amount could exceed insurance coverage of roughly $500 million for 2024 wildfire losses and “could have a material adverse effect on our financial condition, results of operations or cash flows.”  

The Texas House of Representatives created an investigative committee on the wildfires and has held several public hearings. It plans to issue a report in early May. 

Frenzel said the $215 million loss is a preliminary estimate that reflects the low end of a range and is subject to change. He said Xcel is responding to the wildfire risk by accelerating pole inspections and cutting power to lines during dangerous weather, among other measures. 

“Like all utilities, we are experiencing profound changes in weather- and climate-related impacts on our operations,” Frenzel said. “As a result, we must continue to evolve our operations for these unparalleled dynamics.” 

Xcel reported earnings of $488 million ($0.88/share) for the first quarter, compared with $418 million ($0.76/share) in the same period last year. The company said the results reflected increased infrastructure investment recovery and lower operations and maintenance expenses, partially offset by increased interest charges and depreciation. 

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Entergy Earnings Call Focuses on La. Resilience Plan, Nuclear Outage and Settlements

Entergy’s CEO touched on several recent developments on a first-quarter earnings call April 24, including the utility’s recently approved grid-hardening plan for Louisiana, an outage at the Waterford 3 nuclear plant and New Orleans’ acceptance of a settlement concerning Grand Gulf nuclear station.  

Entergy CEO Drew Marsh said Entergy over the quarter made strides in “risk reduction efforts that will benefit our key stakeholders” during the call.  

Entergy reported first-quarter earnings of $230 million ($1.08/share) compared to first-quarter 2023 earnings of $311 million ($1.47/share).  

Entergy CFO Kimberly Fontan said the lower-than-expected earnings can be attributed to mild weather, planned generator maintenance outages and lower sales to cogeneration customers, among other factors.  

Marsh framed the Louisiana Public Service Commission’s April 19 approval of the utility’s $2 billion grid-hardening plan in the state as a positive development.  

“A more resilient grid will also serve as a catalyst for growth as it bolsters confidence for customers seeking to locate or expand in our service area,” he said.  

The PSC approved Entergy Louisiana’s plan just four days after the utility submitted it; consumer advocate groups blasted the process as rushed and only in Entergy’s interest. (See Louisiana PSC Adopts Nearly $2B Entergy Resilience Plan.)  

Marsh said the plan includes 2,100 transmission and distribution projects that will be crucial to communities, and Entergy Louisiana plans to start work immediately. 

Marsh noted Entergy Louisiana also filed for PSC approval of its Bayou Power Station, a $411 million, 112-MW “quick-start, nonbaseload” natural gas power station. He called it an “innovative solution to meet the power needs in a challenging area on the edge of the Eastern Interconnect.” 

The power plant is planned to sit atop a barge in a southern Louisiana canal and could rise with storm surges.  

Marsh drew attention to the New Orleans City Council on April 18 agreeing to a $252 million settlement to resolve its longstanding allegations of mismanagement and poor performance at the Grand Gulf nuclear station in in Port Gibson, Miss. 

The city council settled with Grand Gulf operator and Entergy subsidiary System Energy Resources, Inc. on three fronts: $116 million to resolve allegations around SERI’s mismanagement; $138 million to settle allegations of dubious tax accounting; and $500,000 to lay concerns over reliability to rest. 

“This agreement is consistent with SERI settlements with Mississippi and Arkansas, both of which were approved by FERC and determined to be fair and reasonable. … With the addition of New Orleans, SERI has resolved roughly 85% of its litigation risk,” Marsh said.  

Rod West, president of Entergy utility operations, said Entergy has a shot at pursuing a settlement with Louisiana “in the near term” over Grand Gulf operations now that New Orleans’ litigation is over.  

The Louisiana PSC has been a holdout on a settlement, maintaining ratepayers are owed hundreds of millions of dollars because Entergy mishandled plant operations, undertook an expensive and excessive plant expansion, and engaged in improper accounting and tax violations that shifted costs to ratepayers. (See Former Employee Details Failures at Entergy’s Grand Gulf.)  

Marsh also delivered an update on the offline Waterford 3 nuclear generating station in St. Charles Parish. He said the plant is “working to recover” from a shutdown following a transformer failure. He said the failed transformer was 20 years old, halfway through its expected lifespan.  

“Early indications point to equipment failure as the cause,” Marsh told shareholders.  

In the meantime, Entergy plans to outfit Waterford 3 with an interim, spare transformer to bring the plant to 90% capacity over the summer until a fully compatible replacement transformer arrives, Marsh said.  

“We’re working diligently to bring the plant back online in the coming weeks,” he said.  

Finally, Marsh said Entergy utilities will submit by the end of May six projects furthering the clean energy transition for funding consideration from the U.S. Department of Energy’s Grid Resilience and Innovation Partnership program. Entergy received letters of encouragement on six of the eight preliminary proposals it submitted late last year. Marsh said federal support stands to lower customers’ capital costs. (See Entergy Highlights Data Center and Industrial Load Growth in Q4 Earnings.)  

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Prices, Load Down in MISO March Operations

MISO energy prices plunged on record-low natural gas prices in March while the RTO managed a comparatively lower, 68-GW average systemwide load.  

March average load was lower than MISO’s 71-GW averages in 2022 and 2023, MISO reported.  

The footprint peaked for the month at 84 GW on March 19, lower than March 2023’s 89-GW peak and in line with previous March peaks in 2021 and 2022.  

Real-time locational marginal prices were about $20/MWh for the month as the footprint experienced $1/MMBtu natural gas and $2/MMBtu coal prices. Real-time prices were lower than March 2023’s $26/MWh and less than half of 2022’s $42/MWh.  

MISO’s average 48 TWh of supply came from a mix of 19 TWh of natural gas, 11 TWh of wind, 10 TWh of coal and 7 TWh of nuclear generation. The system again set an all-time solar generation record March 23 when arrays supplied 5.3 GW, or 6% of load at the time. MISO solar generation peaks have become commonplace as more solar projects clear the interconnection queue.  

The RTO averaged 49 GW of daily generation outages over March, more than March 2023’s 45-GW average. 

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Participants ‘Unwaveringly Committed’ to WRAP, WPP CEO Says

DENVER — Western Resource Adequacy Program (WRAP) participants still strongly support the program despite recently appealing to delay its “binding” penalty phase by one year based on concerns about capacity shortages, Western Power Pool (WPP) CEO Sarah Edmonds said April 24. 

But Edmonds acknowledged the appeal clearly signals the RA situation in the West is much more critical than previously thought. 

“[Participants] are still unwaveringly committed to WRAP, which is good news for us, because our belief in the urgency and the need for the program has not changed,” Edmonds said during a panel discussion at the spring joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in downtown Denver. “If anything, it’s only increased in this era of heightened reliability risks and NERC [and] WECC assessments warning us for quite some time that we have a serious issue that we’re facing,” she said. 

Edmonds’ comments came two days after the WRAP’s Resource Adequacy Participants Committee (RAPC) issued an April 22 letter saying program members would postpone binding operations to summer 2027 because some of them confront “significant new headwinds” in securing sufficient energy resources to meet their capacity obligations and avoid heavy penalties in the WRAP’s FERC-approved tariff. (See WRAP Participants Seek 1-Year Delay to ‘Binding’ Operations.) 

The letter cited problems with new resources’ supply chains, forecasts for faster-than-expected load growth and “extreme weather events” that have challenged assumptions about the volume of resources needed to maintain grid reliability as key reasons the delay is required. 

“The RAPC letter is an illustration of the fact that we are shorter than we thought as a collective, and there is not critical mass. And in terms of WRAP, we are facing more resource inadequacy going forward,” Edmonds said. 

Participants are looking to “revisit” WRAP “transition provisions” providing “discounts” to penalties and offer measures “that make it easier to become binding in this program,” Edmonds noted.    

WRAP entities face a May 31 deadline to commit to the binding phase beginning in summer 2026, but stakeholders determined the program would not obtain a “critical mass” of participation by that time, she said. 

The WRAP’s tariff allows WPP to commence binding operations anytime between 2025 and 2028. Participants will work to position the program for participants to commit in May 2025 for the summer 2027 binding phase, a change requiring stakeholder approval. 

“I hope that’s the last marker,” Edmonds said.  “Summer of 2028 is the very last moment — that’s when everyone in this program who’s still there needs to be fully binding.” 

Edmonds said the nonbinding phase of the program still offers “a lot of value.” 

“We’re essentially in an informational stance where we’re going through a lot of the processes — the forward-showing, planning process — and then essentially setting up an operational program that can track how it would really look in real life if we were in this program,” she said.  

“We could do better on all those pieces in terms of the quality of the data that we’re receiving from participants, the amount of data the Western Power Pool is permitted to see in the tariff, and how we can then explain that data and turn that data into information that’s useful for the region,” she added. 

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FERC Sticks with MISO on Queue Penalties over Clean Energy Groups’ Rehearing Attempt

Clean energy groups were unsuccessful with FERC in their challenge of automatic withdrawal penalties in MISO’s interconnection queue.  

The commission decided April 25 that MISO is clear to continue use of an automatic and escalating penalty structure despite a joint rehearing request from the American Clean Power Association, the American Council on Renewable Energy, the Solar Energy Industries Association and Clean Grid Alliance (ER24-340).  

“Commission precedent and the record in this proceeding demonstrate that interconnection withdrawals create a generalized harm in MISO that more than inconveniences remaining interconnection customers in MISO’s interconnection queue,” FERC wrote to justify MISO’s penalty setup.  

Under the penalty schedule, MISO can keep 10% of a developer’s per-megawatt milestone fees at the queue’s first decision point, 35% by the second decision point, 75% by the time their project reaches the third and final phase of the queue and, finally, 100% if they drop out during the negotiation stage of the generator interconnection agreement. 

The penalty fees were imposed early this year as part of a package of rules meant to downsize MISO’s interconnection queue and discourage speculative projects. This week, MISO announced it received 123 GW of project proposals under its 2023 queue cycle, less than the 171 GW it fielded in 2022. (See MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle.)  

The clean energy groups had argued the penalties would have a chilling effect on generation entering the MISO queue because the fees would rack up before developers receive meaningful study results from the RTO on the feasibility of their projects. They argued FERC treaded on its own philosophy that penalties shouldn’t discourage interconnection customers from lining up projects or withdrawing them in an orderly fashion. (See Clean Energy Groups Seek FERC Re-evaluation of Automatic Penalties in MISO Queue.)  

However, FERC said the penalties will persuade developers to withdraw nonviable projects “before MISO has expended significant resources studying such requests.” It also said its precedent doesn’t necessarily prohibit automatic fines.  

“We find that neither the establishment of an automatic withdrawal penalty nor the amount of the penalty creates a barrier to enter MISO’s interconnection queue; rather, such a penalty reinforces an existing consequence of withdrawing an interconnection request,” FERC said. “While it is true that [penalties] may discourage the submission of speculative interconnection requests or encourage earlier withdrawals to avoid higher penalties, those outcomes are not unreasonable barriers to entering the interconnection queue.” 

FERC also agreed with MISO that automatic forfeitures will serve as an “appropriate mechanism to disincentivize speculative interconnection requests from entering the queue.” 

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Texas RE Auditors Push Preparedness for Security Walkthroughs

Compliance auditors at the Texas Reliability Entity urged utilities April 24 to think of them not as antagonists looking to get them in trouble, but as allies in the mission of maintaining grid reliability. 

“We’re not looking for more work,” Paul Hopson, compliance team lead at Texas RE, said at the regional entity’s Spring Standards, Security and Reliability Workshop in Austin. “We’re looking for compliance, of course. We want to help you get there. Believe me, we will. We’ll stay there all week … and even more time if we need to, to help you show compliance. If you need more time, we’ll be happy to review whatever you want to give us to look at. But our job is to ensure the reliability and stability of the grid.” 

Hopson’s presentation focused on how responsible entities should prepare for walkthroughs performed during audits related to NERC’s Critical Infrastructure Protection (CIP) standards, which govern both physical and digital security. He said walkthroughs can help identify issues in both areas. 

Entities often think of physical security as limited to installations, like fences, gates and barriers to deter unauthorized access, cameras to monitor activity around the site, and access-control measures such as keycard readers and alarms, Hopson said, with cybersecurity seen as a separate specialty. 

However, he noted there is actually considerable crossover between these areas. For example, CIP-006-6 (Cybersecurity — Physical security of BES cyber systems) requires entities to secure the physical points of access to certain grid cybersystems. As a result, utilities should be aware that cybersecurity audits may involve site visits in addition to software inspections. 

“When we go on-site, and we’re doing these reviews … we’re going to look through these things,” Hopson said. “We may not check every door lock; we may not look for every cyber asset that … wasn’t in scope. But since we’re there … we’re going to try to point out any vulnerabilities.” 

Hopson was asked what auditors would do if they noticed a deficiency with a CIP standard that was outside the scope of their audit. He acknowledged that while the team would not expand the scope on the spot, “if there’s something that … leads to a noncompliance, yeah, we are going to have to have that discussion” with the utility’s staff. 

He emphasized that this is not just a hypothetical situation, but something his team has encountered numerous times. When he joined the compliance team in 2016, Texas RE auditors performing compliance checks for CIP-012-1 (Communications between control centers) also frequently would find issues with the CIP-006 standards. 

Although they did not specifically check for such problems, they were easy to spot for auditors familiar with both standards because the CIP-012-1 audit required they be in control centers where the access hardware for cybersystems was visible. 

Hopson said that entities have been “doing a much better job” with CIP-006 compliance in recent years, but auditors still keep their eyes open when performing a CIP-012 audit because “that’s just part of our risk-based approach.” When asked what long-term effects such a finding would have besides a recommendation to the registered entity involved, Hopson acknowledged auditors would notify the RE’s Risk Department, and the CIP-006 deficiency “may end up on an audit in the future.” 

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EPA Antes up Nearly $1B to Replace Diesel Heavy-duty Vehicles

EPA on April 24 announced nearly $1 billion in grants from the Inflation Reduction Act to help cities, states, territories and school districts trade in their older, diesel-burning heavy-duty trucks and buses for new zero-emission vehicles.  

The $932 million competitive funding opportunity for the 2024 Clean Heavy-Duty Vehicles Grants Program is aimed at covering part of the cost of a range of Class 6 and 7 HDVs, as well as charging equipment and workforce training programs. 

Class 6 vehicles (19,501 to 26,000 pounds) include school buses; bucket trucks, such as cherry pickers; and different kinds of delivery vehicles, referred to as step vans and box trucks. Class 7 vehicles (26,001 to 33,000 pounds) include transit buses, garbage trucks and street sweepers. 

According to EPA, more than 3 million Class 6 and 7 HDVs are on the roads in the U.S. Transportation accounts for 29% of U.S. greenhouse gas emissions, and medium- and heavy-duty trucks make up 23% of that total, according to the agency. 

The “historic” funding will help “ensure every community can breathe clean air,” EPA Administrator Michael Regan said in a statement. The IRA dollars also could advance U.S. competitiveness in international markets, Regan said, securing “our nation’s position as a global leader in clean technologies that address the impacts of climate change.” 

Sue Gander, director of the World Resources Institute’s Electric School Bus Program, hailed the new funding as “a game changer for communities across the country that want to transition to clean buses and trucks — and breathe cleaner air — but don’t have the means to do so. … 

“Heavy-duty vehicles emit huge amounts of air pollution that harm the health and wellbeing of our children and communities. Historically underserved communities living near depots, ports and highways are often more exposed to pollution from these vehicles, underscoring the equity benefits of this program,” Gander said in a statement on the WRI website. 

According to the funding announcement, EPA expects to award approximately 40 to 160 grants, ranging from $500,000 to $60 million per award. The deadline for applications is July 25, with awards announced and finalized by the end of the year. 

The awards will be split between two subprograms, with 70% of total funds going to school buses and 30% for “vocational vehicles,” which include other types of Class 6 and 7 HDVs. 

Other carveouts require that $400,000 of the grants be awarded in “nonattainment” regions that do not meet national air quality standards, and at least 15 grants go to tribal groups and territories. 

States, territories, cities, public school districts, tribal governments and nonprofit school transportation associations are eligible for the funds. 

Cost shares for the grants will depend on the type of HDV and whether it is a battery-electric or hydrogen fuel cell vehicle. The lowest cost share is 33% for an electric transit bus, and the highest is 80% for a range of hydrogen fuel cell Class 6 vehicles. 

EPA’s top priority for replacements are diesel-powered HDVs from model year 2010 or earlier, but other HDVs with internal combustion engines and from model years 2011 and after also may be eligible. The new electric or fuel cell HDVs should be from model year 2023 or later. 

Awards can also be used to cover behind-the-meter charging infrastructure — from Level 2 chargers and battery storage units to new electric panels and meters — but not transformers. 

Clean Freight Strategy

The HDV grant program was one of a series of April 24 funding announcements from the Biden administration to promote a new initiative aimed at setting a national goal for the U.S. to develop a zero-emissions freight strategy, covering trucks, rail, aviation and marine vehicles. 

The administration has committed to working with other countries to build clean HDV markets in which 30% of new medium- and heavy-duty vehicle sales will be zero-emission by 2030 and 100% by 2040, according to a White House fact sheet. 

The Department of Transportation announced $148 million for 16 grants to 11 states and Puerto Rico “to improve air quality and reduce pollution for truck drivers, port workers and families that live in communities surrounding ports.” 

The grants are the first round of the department’s $400 million Reduction of Truck Emissions at Port Facilities Grant Program, created by the Infrastructure Investment and Jobs Act. 

For example, Georgia is receiving $15.3 million to build a large-scale charging project near the Port of Savannah, which will allow the replacement of diesel-powered trucks and expand the use of other low- and zero-emission equipment at the port. 

“When truckers spend hours idling at ports, it’s bad for drivers, bad for supply chains and bad for nearby communities that feel the brunt of more polluted air,” Transportation Secretary Pete Buttigieg said in a statement. “The investments we are announcing … will save truck drivers time and money and help ports reduce congestion and emissions, while making the air more breathable for workers and communities.” 

According to the White House, the Department of Energy is also putting up $72 million for a “SuperTruck: Charged” program to demonstrate how vehicle-to-grid integration at depots and truck stops will “provide affordable, reliable charging while increasing grid resiliency.” 

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Policymakers Chart FERC’s History of Opening the Grid for Competition

FERC has worked to restructure the power industry for nearly three decades, and now it is poised to take another major step forward on that front with the transmission rule next month, panelists said on a webinar April 24 hosted by Americans for a Clean Energy Grid. (See FERC Observers, Stakeholders Lay out What is at Stake with Tx Rule Looming.) 

Congress first started opening up the grid with the Public Utility Regulatory Policies Act in 1978, said Sen. Ed Markey (D-Mass.), noting that he supported the law just after being elected to the House of Representatives. 

“For the first time, utilities had to buy power from qualifying small generators that were not utilities, but utilities didn’t want to give up ownership of the transmission system,” Markey said. “They didn’t want anyone else to have real access. And we had won a battle on interconnection, but we had not won the war.” 

ferc grid

Sen. Ed Markey (D-Mass.) addresses ACEG’s webinar on April 24. | ACEG

It took more than a decade for Congress to take up the Energy Policy Act of 1992, which included language requiring open access to utilities’ transmission lines that Markey had worked to introduce from his seat on the Energy and Commerce Committee. 

“I had to negotiate with the Senate Energy [and Natural Resources Committee] chairman, Sen. Bennett Johnston [D] of Louisiana, who had a utility that was … I’ll put it like this: hesitant to adopt it,” Markey said. “That’s not their natural attitude down there in Louisiana and Arkansas to welcome competition, but it got included. But still, the utilities did successfully limit the scope of open access. So, if a small generator wanted transmission access, they had to file for it.” 

At that point, FERC stepped in and issued Order 888 in 1996 that required all utilities under its jurisdiction to have full open access of their transmission systems and led to the restructuring of the wholesale side of the power industry, he added. 

“Look, 888 was a huge, great beginning,” said former Commissioner Nora Mead Brownell. “But let’s face it: Monopolies do not go well quietly into the night. So, when we got to FERC, there was the California energy crisis, which we had to solve.” 

The 2000-2001 energy crisis involved a lot of litigation and FERC creating the Office of Energy Infrastructure Security, the focus of which was underinvested in by California — making the crisis possible, Brownell said. 

FERC always has commissioners appointed by both political parties, and while the commission in the early aughts had plenty of behind-the-scenes debates on specific policies, they were all moving in the same direction to open up the markets, she said. That commission, led by Chair Pat Wood III, approved new RTOs and helped to lay some of the basic rules for their markets out. 

Prior to his election to Congress in 2018, Rep. Sean Casten (D-Ill.) worked in the industry developing power plants. He recalled Congress’ and FERC’s work to raise nuclear plant capacity factors and roll out combined cycle plants around the country. 

“Why did markets do that?” Casten said. “Well, they did that because regulated utilities are really good at reliability; they are really good at keeping the lights on. They are really bad at innovation and really bad [at] cost planning. That’s not a criticism; the market needs both things.” 

Order 888 gave industry participants the ability to make money by deploying cheaper assets for the first time in the power industry’s centurylong history, he added. It also proved to be a win for the environment, as it ensured coal plants would face competition, to which they lost, Casten said. 

FERC has been tweaking the rules of markets ever since, but Casten said that so far, it has fallen short of major reforms to curtail market power and get beyond the still-often-fragmented nature of the grid. 

“They’ve been really too slow in addressing interregional issues, cost issues [and] the growing interconnect delay on the system,” Casten said. “Those are problems they have the jurisdiction to fix. And we’re out of time for talk; we got to start moving forward.” 

Markey also called for further reforms, noting the country needs to double the pace of transmission expansion to fully use the incentives from the Inflation Reduction Act and build even more lines to hit net-zero targets. 

Brownell wants to see FERC step up its monitoring abilities so it can get a better handle on market power issues but also be informed about the planning issues, on which it tends to default to the information provided it by the ISO/RTOs. 

“I think we could use [the Department of Energy] as a backstop to validate some of the planning assumptions and plans that come out of the RTOs,” Brownell said. “I think the RTOs are doing the best they can under the circumstances. I don’t think we’re rewarding them for the right things, and I don’t think we’re rewarding them for making progress.” 

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Congestion Revenue Rents Still Underfunded, CAISO DMM Says

Congestion revenue rights (CRRs) auctions averaged $62 million in losses between 2019 and 2023, down nearly $50 million since changes were implemented in 2019 but “still very high,” said CAISO’s Department of Market Monitoring (DMM) during the ISO’s Annual Policy Initiatives Roadmap Process meeting April 22. 

CAISO staff and stakeholders questioned if the consistent underfunding of CRRs should be taken up as an official initiative. 

CRR auctions have been losing money for more than a decade, and CAISO has taken multiple steps to address the revenue inadequacy. In 2019, the ISO instituted rule changes meant to decrease the amount of money flowing from ratepayers to commodities traders, which reduced losses significantly, the DMM said. (See CAISO CRRs Still Losing Money, but Less.) Auction revenues for transmission ratepayers averaged 67 cents per dollar paid to CRRs since 2019, compared to about 48 cents before the changes. Almost all losses stem from rights bought by financial traders, according to the DMM. 

In May 2020, CAISO released a report evaluating the rule changes and identified that an issue with the shift factor threshold — which is used to evaluate the effectiveness of energy bids to manage congestion in the clearing of the day-ahead market — was causing additional underfunding. 

“Even though the CAISO did address that issue, we are still seeing quite a bit of revenue inadequacy and underfunding,” Kallie Wells, senior consultant at Gridwell Consulting, said in her presentation on the issue. 

The changes implemented to address the shift factor threshold primarily impacted low-voltage lines, Wells said, with recent CRR revenue inadequacy affecting higher voltages. However, 25% of low-voltage constraints still saw recent funding levels of just 20%. Underfunding appears to be related to more than just transmission derates, Wells added, questioning the root causes of the continued revenue inadequacy. 

“The ask that we have of … CAISO to include in terms of potential scope on a CRR enhancements policy is really getting at what are the root causes or drivers of the current revenue inadequacy,” Wells said. “It’s really unclear to us what those underlying factors are and whether or not they continue to align with cost causation principles.” 

Because of how CRRs are allocated, rights are becoming a liability rather than a reliable source of revenue, Wells said. And congestion is increasing; she pointed out that the first quarter saw the most congestion in five years, further emphasizing the importance of CRRs in CAISO’s market. 

“The role that CRRs play is extremely important in an organized energy market, and if we’re having this issue with how the shortfall is being allocated to the CRRs and causing the CRRs to be a risk or a liability for entities to hold and not functioning properly as a hedging tool, that’s extremely concerning,” she said. 

Wells provided policy suggestions for addressing the problem, including capping underfunding and using more overfunding to offset deficits. 

DMM Again Recommends Replacing CRR Auctions

The DMM continues to suggest that forgoing the CRR auction in place of a financial market based on offers from willing sellers could solve the underfunding problem. 

“Ever since CRRs were implemented over 10 years ago, the auction revenues that are brought in in the auction fall way short of the congestion revenues that get paid out,” said Eric Hildebrandt, the department’s executive director. “So, from that perspective, there is a net loss to transmission ratepayers as a result of the CRR auction. 

“The difference in the DMM proposal from the market that exists today is, rather than the ISO auctioning rights … there would be a financial auction in which those entities that held rights could offer them for sale to other entities.” 

Under the proposal, CRR allocations could remain unchanged, or alternatively, congestion revenues could be refunded to load-serving entities instead of being allocated. A purely financial CRR market would be run with other voluntary bids to buy and sell CRRs and “would be easier and less subject to errors than [the] current CRR model based on a physical network,” Hildebrandt said. 

But some stakeholders raised concern that replacing the auction with a financial market could stifle competition and liquidity. 

“With auctions, the reason we have more than just load-serving entities participating in them is to inject competition into the market,” said Noha Sidhom, an Energy Trading Institute board member. “And so, my concern when I hear some of this is I just worry about lack of competition and lack of liquidity.” 

Seth Cochran, head of strategic market policy at Vitol, echoed Sidhom’s concerns. 

“There’s a strong assumption embedded in here that you can create a replacement market and everything will be fine,” he said. “I know you’re trying to put together a substitute here, but I can tell you from decades of experience in the market that you’re just not going to be able to foster liquidity, and it’s really going to leave the [independent power producers] out to dry. I know it might sound good on paper, but this is totally untested and unproven.” 

Because of prior commitments from the ISO and the Market Surveillance Committee to address the issue, the DMM recommended the topic not be taken up as a discretionary initiative and received stakeholder support. Hildebrandt did note, however, that while CAISO and the committee began discussion of CRR losses in 2023, they’ve “been silent since.”